In many light oil (32°-40° API gravity) reservoirs and some medium oil (20°-32° API gravity) reservoirs, the original oil in place (OIP) may be recovered in three stages. In an initial stage, usually termed primary production, oil typically flows from the wells due to the intrinsic reservoir pressure. Ordinarily, only a fraction of the original OIP is produced by this method, very roughly up to about 20% of the original OIP. Waterflooding, a secondary recovery technique, is typically the next stage in this sequence and yields additional oil, very roughly for example up to an additional 30% of the original OIP. After this point, the cost of continuing the waterflood usually becomes uneconomical relative to the value of the oil produced. Hence, as much as 50% of the original OIP can remain even after a reservoir has been extensively waterflooded. Tertiary recovery methods may be used in the last stage in the sequence. This stage may utilize one or more of any other known enhanced oil recovery methods; e.g., polymer flooding or CO2 flooding.
Practices for waterflooding of conventional light oils were initially researched in the 1940's by Buckley et al. in “Mechanism of Fluid Displacements in Sands”, AIME Vol. 146, pages 107-116 (1942) and little has changed since the work by Craig in “The Reservoir Engineering Aspects of Waterflooding” American Institute of Mining, Metallurgical and Petroleum Engineers, Inc. (1971). Even as recently as 2004, those in industry report that most of the sources refer to waterflooding oils of viscosity of less than 100 mPa·s, see e.g., Smith et al. “Waterflooding”, Advanced Waterflooding Course, Society of Petroleum Engineers, Canadian Section, Calgary, Alberta (Apr. 19-23, 2004). The major precepts of classical light oil waterflooding have been: start early; and completely replace reservoir voidage (VRR=1). Maintaining an even VVR, i.e., a VRR of 1, is so ingrained in industry theory and practice today, that Canadian producers must get permission from government regulators to deviate the VRR from a value of 1. Chawathé et al. studied large Middle-Eastern waterfloods and have actually recommended a cumulative VRR of more than 1.2 for peripheral floods.
Oil recovery through use of secondary methods employing displacement fluids, such as waterflooding, is usually inefficient in subterranean formations (hereafter also simply referred to as formations) where the mobility of the in-situ oil being recovered is significantly less than that of the drive fluid used to displace the oil. Mobility of a fluid phase in a formation is defined by the ratio of the fluid's relative permeability to its viscosity. When the displacing fluid is water, the displacement typically becomes inefficient for oils with a viscosity of greater than, for example, 10 cp.
In particular, when waterflooding is applied to displace very viscous or heavy oil from the formation, the process is very inefficient because the oil mobility is so much less than the water mobility. As used herein, the term “viscous or heavy oil” means an oil of 30° API gravity or less, and generally less than 25° API. Some typical heavy oil reservoirs in the State of Alaska, USA or Canada can exhibit a gravity of less than 17° API.
Notwithstanding such inefficiency, waterflooding is becoming increasingly important in recovering heavy oil. In Western Canada, 5200 million m3 of heavy oil is estimated to be in place in Alberta and Saskatchewan. However, only a fraction of this heavy oil is being recovered by more than 200 waterflood operations, with a typical recovery of about 24% of the reservoir's oil in place. An improvement in waterflooding these reservoirs of even a few percent could result in recognition of a substantially greater amount of recoverable reserves.
Consequently, in past waterflooding operations, it has been felt that there is a need to either make the water more viscous through use of particulates, polymers, or other chemical agents, or to use another drive fluid that will not “finger” as easily through the oil. Due to the large volumes of drive fluid needed, the proposed drive fluid must be inexpensive and stable under formation flow conditions. Oil displacement is most efficient when the mobility of the drive fluid is closer to or less than the mobility of the oil, so it would be advantageous to develop a method of generating a lower mobility drive fluid in a cost-effective manner. For modestly viscous oils—those having viscosities of approximately 20-100 centipoise (cp)—water-soluble polymers such as polyacrylamides or xanthan gum have been used to increase the viscosity of the water injected to displace oil from the formation. With this process, the polymer is dissolved in the water, increasing its viscosity.
While water-soluble polymers may be used to achieve a favorable mobility waterflood for relatively low viscosity oils, usually the process cannot economically be applied to achieving a favorable mobility displacement of more viscous or heavy oils. These oils are so viscous that the amount of polymer needed to achieve a favorable mobility ratio would usually be uneconomic. Further, as known in the art, polymer dissolved in water often is desorbed from the drive water onto surfaces of the formation rock, entrapping it and rendering it ineffective for viscosifying the water. This leads to loss of mobility control, poor oil recovery, and high polymer costs. For these reasons, use of polymer floods to recover oils in excess of 100 cp is not usually technically or economically feasible.
Other methods employ various chemical or particulate emulsifying agents or emulsions themselves for enhanced oil recovery, as can be seen in U.S. Pat. Nos. 2,731,414; 2,827,964; 4,085,799; 4,884,635; 5,083,612; 5,083,613; 6,068,054; and 7,186,673. While these methods may help increase the recovery of oil, they are relatively expensive and difficult to employ in practical use.
McKay, in U.S. Pat. No. 5,350,014, discloses a method for producing heavy oil or bitumen from a formation undergoing thermal recovery. Production is said to be achieved in the form of oil-in-water emulsions by carefully maintaining the temperature profile of the swept zone above a minimum temperature. Emulsions generated by such control of the temperature profile within the formation are thought to be useful for forming a barrier for plugging water-depleted thief zones in formations being produced by thermal methods, including control of vertical coning of water. However, this method requires careful control of temperature within the formation zone and, therefore, is useful only for thermal recovery projects. Consequently, the method disclosed by McKay could not be used for non-thermal (also referred to as “cold flow”) recovery of heavy or viscous oil.
More recently, Vittoratos et al. in “Flow Regimes of Heavy Oils under Water Displacement” 14th European Symposium on Improved Oil Recovery, Cairo, Egypt (Apr. 22-24, 2007), describes an analysis of certain heavy oil waterflood data.
The relevant teachings of the patents and publications mentioned herein are incorporated by reference.
As can be seen, there is a need for improved methods of producing heavy or viscous oils from subterranean formations so that more of the OIP can be recovered therefrom, and particularly, there is a need for methods which can be implemented economically and that are capable of performing well under a wide range of formation conditions.